LONDON (Reuters) – More than ever before, U.S. shale producers are becoming the victims of outdated restrictions on the export of crude oil from the United States.

Export controls have ensured the most oversupplied part of the global oil market is at home in the United States.

The main beneficiaries are rival producers in the Middle East and elsewhere able to obtain higher international prices thanks to the export ban.

U.S. shale producers have received almost no benefit from the improvement in international oil prices since the middle of January.

Benchmark Brent prices have risen around $16 per barrel since hitting their recent low on Jan 13. But prices for shale producers are tied to the domestic marker WTI which has risen by only $4 per barrel over the same period (link.reuters.com/buv24w).

In the middle of January, posted prices for shale producers in Texas and North Dakota were about $4.50 and $17 less than the international marker respectively. By the end of February, the discounts had widened to $16 and $29 (link.reuters.com/duv24w).

Wellhead prices have been pinned down to a level where only the most productive wells in the most productive shale plays will breakeven.

As a result of the growing gap between Brent and WTI, the whole burden of supply-side adjustment in the oil market continues to be thrown onto U.S. shale producers.

Some analysts have questioned whether the rally will delay the necessary rebalancing of the oil market by encouraging more shale production in the United States.

But the price history shows there is little real danger: higher world oil prices have not filtered though into an improvement in the prices and revenues received by shale producers at home.

Instead, American oil producers are being forced to cut their output because they cannot compete aggressively in export markets.

The slump in prices has demonstrated the distortions caused by the export control regime and the damage it is doing to the U.S. oil industry in terms of lost jobs, tax revenues and oil production.

Eliminating the export controls might only raise prices for U.S. producers by a few dollars per barrel. But at the moment those few dollars are the difference between profit and loss for large parts of the shale industry.

Removing the antiquated export ban is the only way to enable U.S. shale producers to compete fairly in the global oil market, protect jobs and promote energy security.

LONDON, Feb 27 (Reuters) – U.S. refineries are processing
record quantities of heavy crude from Canada as the perfect
complement to light oils from North Dakota and Texas as they
struggle to keep their average blend steady.

Crudes vary enormously – from low-density oils with few
impurities to much denser oils containing a relatively high
percentage of sulphur and heavy metals such as nickel and
vanadium.

Bakken and Eagle Ford are light, sweet oils, while Saudi
Arabia’s Arab Heavy and Alberta’s Western Canadian Select are
much heavier and sourer.

The density of crudes is normally expressed in terms of
degrees API, which compares oil to the density of water at a
standard temperature of 60 degrees Fahrenheit.

Crude density ranges from 42 degrees API for Bakken (which
makes it about 80 percent as dense as water at standard
temperature) to 27 degrees for Arab Heavy (89 percent as dense
as water) and 22 degrees for Western Canadian Select (93 percent
as dense as water).

But the big differences are easier to understand by
switching to more familiar units. A cubic metre of Bakken crude
weighs around 815 kg, compared with 885 kg for Arab Heavy and
925 kg for Western Canadian Select.

STEADY DIET

While the qualities of crudes vary widely, U.S. refiners
have discerning requirements. The average density of crude
processed in U.S. refineries has been steady, varying by only 3
degrees over the last three decades, or about 17 kg per cubic
metre, according to the U.S. Energy Information Administration
(EIA).

U.S. refiners like to process crudes averaging around 30-32
degrees API, or between 865 and 875 kg per cubic metre (link.reuters.com/vys24w).

Refineries achieve this remarkably steady performance by
blending crudes to achieve a combined feed as close as possible
to the ideal.

Bakken, at just 815 kg per cubic metre, is much lighter than
the 865-875 kg refineries are trying to achieve. Eagle Ford is
lighter still.

U.S. refiners have responded to the rising output of very
light domestic crudes by cutting back purchases of other light
oils from abroad while importing more heavy crudes to keep the
average density roughly constant.

Strict blending requirements explain why U.S. imports of
light oils from countries such as Nigeria have dwindled to
almost nothing while refiners import record quantities of much
heavier oil from Canada.

In fact, Western Canadian Select (WCS) is the perfect
complement for shale oil production from the Bakken and Eagle
Ford.

WCS is around 55 kg per cubic metre heavier than refiners
would like on average, while Bakken is around 55 kg too light,
so they blend perfectly with one another (link.reuters.com/jat24w).

In practice, blending is slightly more complicated than this
simple example. However, heavy crude oils from Alberta are the
perfect blending partners for light crudes from the main shale
plays in North Dakota and Texas.

As a result, U.S. imports from Canada reached almost 3
million barrels per day in the final months of 2014, up from
less than 2 million bpd in 2010, according to the EIA.
(link.reuters.com/sat24w)

KEYSTONE CRUDE

President Barack Obama has implied that the proposed
Keystone pipeline would be of little benefit to U.S. refiners
because it would carry Canadian crude across the United States
for export to foreign markets.

“Understand what this project is,” the president said during
a November visit to Myanmar. “It is providing the ability of
Canada to pump their oil, send it through our land, down to the
Gulf, where it will be sold everywhere else.”

The president was poorly briefed. U.S. refineries are
processing record volumes of Canadian oil, even as U.S.
production is rising, and they are hungry for more. Canadian oil
is being processed together with U.S. shale oil to enable U.S.
refineries to make best use of their equipment, which is why
refiners support Keystone.

Without more imported Canadian oil, which could come via
pipeline or on rail cars, refineries will have to turn to other
suppliers of heavy crude. The prime candidates would be
Venezuela, Saudi Arabia, Iraq and Mexico.

Quality issues also explain why there is a compelling case
to permit more U.S. domestic crude to be exported rather than
refined at home. U.S. refineries cannot simply refine more U.S.
production (weighing 815 kg per cubic metre) by replacing
Canadian crude (weighing 925 kg).

Policymakers who suggest the United States need not build
pipelines from Canada, and should maintain restrictions on the
export of domestic crude to promote national energy security, do
not understand how refineries operate.

LIGHTER BARRELS

U.S. refineries are already struggling to maintain their
preferred blend in the face of a torrent of light oil from
Bakken, Eagle Ford and the Permian Basin.

Even with rising Canadian imports, the average API gravity
of crude processed at U.S. refineries has risen from a recent
low of 29.9 degrees in June 2008 to a high of 31.8 degrees in
September 2014.

In the 12 months to September, average API gravity rose by
almost a full point, which is an enormous shift in such a short
time.

In the short term, refineries have some operational
flexibility. But the record suggests this flexibility is limited
to changing the average crude mix by 2 or 3 degrees API at most.

U.S. refineries cannot run on an exclusive diet of 40 degree
shale oil without enormous and expensive investment in new
equipment.

Production from the major U.S. shale plays is likely to
flatten this year after growing by around 1 million barrels per
day in both 2013 and 2014.

But if shale starts growing again in 2016 and 2017, it will
need to be coupled with increased imports from Canada and a
liberalisation of U.S. export restrictions to avoid severe
operational distortions in the U.S. refining system.

LONDON, Feb 25 (Reuters) – North Dakota’s oil producers have
pulled back to the core areas of the Bakken formation to cut
costs and maximise output amid the slump in prices.

The number of active rigs in the state has fallen to just
121, from 190 a year ago, according to an active rig list
published by the state’s Department of Mineral Resources (DMR)
on Wednesday. (here)

The rig count is now below the threshold of “at least 130″
DMR Director Lynn Helms identified last month as needed to
sustain output at the current level of just over 1.2 million
barrels per day.

But more important than the raw number is their distribution
across the state, with drilling now increasingly concentrated in
only the most promising areas.

Of the 121 rigs active on Wednesday, 115 are drilling in
just four counties at the heart of the Bakken – Dunn, McKenzie,
Mountrail and Williams.

The number of rigs operating in the core has fallen by 30
percent from 165 on Dec. 12, according to DMR records.

The four core counties accounted for 89 percent of the
state’s oil production in December, a little over 1 million
barrels per day.

Only six rigs are operating outside the core counties, down
from 17 in mid-December, a decline of 65 percent.

Non-core counties produced just 128,000 barrels per day in
December, so they account for a trivial amount of output on a
national scale.

Some analysts argue that producers will be able to offset
the smaller number of rigs by concentrating them in only the
most prolific parts of the Bakken.

But with the number of rigs in even the core areas down by
30 percent in just over two months, it seems more likely
production will begin to plateau or fall in the coming months.

Once the backlog of well completions inherited from 2014 is
worked off, which will take another two to three months, decline
rates from existing wells should match or overtake production
from the smaller number of new wells being drilled.

LONDON, Feb 25 (Reuters) – “Because this act of Congress
conflicts with established executive branch procedures and cuts
short thorough consideration of issues that could bear on our
national interest – including our security, safety and
environment – it has earned my veto.”

With those words, the president returned the Keystone
pipeline authorization act (S.1) to the Senate unsigned, and
challenged lawmakers to find the two-thirds majorities in both
houses needed to enact the law without his approval, something
that remains unlikely.

But by citing established procedures and the need not to
short cut a thorough examination of the issues, after more than
six years of environmental reviews, the president’s staff
demonstrated they have absolutely no sense of irony and a deeply
cynical approach to governing.

The president’s advisers insist the administration has not
yet taken a decision on the merits of the pipeline and is still
waiting for the State Department to finish its long-delayed
review.

The president’s spokesman has insisted it is still
“certainly possible” that he could authorise the pipeline in the
normal way if he concludes that is in the national interest.

The administration insists its objections are procedural and
centre on the attempt to take a decision that is notionally
about foreign relations, a traditional area of executive branch
prerogative, out of the president’s hands.

But the fiction that the administration is keeping an open
mind about the project while insisting the normal process is
observed is becoming impossible to sustain.

The president himself has made a series of increasingly
critical comments in recent months about the pipeline which
strongly suggest he has made up his mind to reject it.

BROKEN PROCESS

Keystone has become a totemic issue for both environmental
campaigners and the oil industry, which has been used to
mobilised passions out of all proportion to the significance of
a single pipeline.

But it is also a symbol of a broken decision-making process
that should be overhauled to ensure the United States can meet
the urgent energy and environmental challenges of the 21st
century.

TransCanada submitted an application for a
presidential permit to build the pipeline in September 2008 and
2,350 days later the administration is still unable to provide a
timetable for making a final decision.

The exhaustive review process has generated literally
thousands of pages of analysis – covering everything from its
impact on groundwater (40 pages), vegetation (50) threatened and
endangered species (130) and socioeconomics (110) to take just a
few examples.

Keystone has kept dozens of lawyers, lobbyists, economists,
bureaucrats and specialists in environmental impact statements
in highly-paid full-time employment for years.

And still the administration says it needs more time to
study the issues and reach a decision on whether the pipeline is
in the national interest.

Protecting the environment and taking action on climate
change are important. Major infrastructure projects deserve
thorough review. But taking decisions in a timely manner is also
important. And in this case, the administration has failed.

In one sense, Keystone is unusual: most applications to
build pipelines and power lines across the U.S.-Canadian border
have been approved swiftly.

But in another it is emblematic: the preparation of
environmental impact statements and authorisations for major
energy infrastructure projects has become a source of lengthy
delays.

Delay has become the favourite weapon to kill projects to
which environmental groups object, as Michael Graetz of Columbia
Law School has explained (“The End of Energy” 2011).

“Litigation to enforce new legislative requirements,
especially for environmental impact statements, (has) made
placing new sources of energy in service much more difficult and
expensive,” Graetz wrote.

“Environmental activists had mastered techniques that at a
minimum served to delay energy projects and make them more
costly, but that in many instances also succeeded in killing
projects altogether.”

DELAY AND KILL

The biggest victim of the delay-and-kill strategy has been
nuclear power, which some prominent climate campaigners now warn
is essential to stemming catastrophic climate change.

But the same strategy is now being used to delay and block
Keystone as part of a broader effort to halt the exploitation of
Canada’s oil sands.

The National Environmental Policy Act (NEPA) of 1969 had
strong bipartisan support and was passed by a
Democrat-controlled Congress and signed into law by Republican
President Richard Nixon.

NEPA was approved by the House of Representatives by a
lopsided majority of 372-15 and unanimously by the U.S. Senate.

“Restoring nature to its natural state is a cause beyond
party and beyond factions. It has become a common cause of all
the people of this country,” Nixon told Congress in his annual
address in 1970.

But NEPA was never intended to become a source of endless
decision-making delays or a full employment act for lawyers,
lobbyists and environmental specialists.

The distortion and manipulation of the NEPA process has
brought the entire system into increasing disrepute and made it
an issue of contention between the parties.

For the White House, liberal Democrats and environmental
groups the issue is not Keystone but the broader fight against
climate change.

For most Republicans, Democrats from energy producing
states, and large parts of the petroleum industry and the wider
business community, however, the issue is becoming whether the
NEPA process is broken.

As the Keystone process slouches onwards, it is hard not to
conclude something has gone terribly wrong with the
decision-making process in this case and for energy projects
more generally.

With its constant promises, a decision can be expected soon,
followed by more excuses for delay, statements that the
administration is keeping an open mind, followed by critical
statements about the project, the decision-making process has
appeared neither transparent nor honest.

If the president wanted to make a symbolic gesture on
climate change, and please his supporters in the environmental
movement, by refusing the pipeline, he should have done so years
ago and made his objections plain.

Instead, his administration has cynically spun out the
process to avoid taking a controversial decision and diminished
the credibility of the entire presidential permitting and NEPA
process.

LONDON, Feb 23 (Reuters) – Train derailments involving crude
oil and ethanol in the United States will cost more than $18
billion over the next 20 years, according to an assessment by
the U.S. Department of Transportation.

USDOT forecasts there will be just over 200 derailments
involving trains carrying 20 or more tank cars of crude or
ethanol between 2015 and 2034, an average of more than 10 per
year, based on analysis of previous accidents and predicted
growth in traffic volumes.

Most will be “lower-consequence events” involving limited
damage to property, environmental clean-up and only a few
injuries or fatalities, with the bill totalling less than $5
billion.

But up to 10 could have more serious consequences because
they occur in more densely populated areas, with an estimated
cost of $1.2 billion per incident.

USDOT also considered a tail-risk event occurring in a
densely populated urban centre such as Chicago and estimated the
damages from a single incident could amount to $6 billion.

However, the maximum insurance coverage available in the
commercial rail insurance market is limited to around $1 billion
per carrier, per incident, according to USDOT, so railroads are
under-insured against the risk of a catastrophic accident.

The estimates were first reported by the Associated Press on
Sunday (“Fuel-hauling trains could derail at 10 a year”).

They are contained in a draft regulatory impact analysis
prepared by USDOT to support its proposed new rules on tank cars
and railroad operations, and can be downloaded from
www.regulations.gov or the Internet using the document code
PHMSA-2012-0082-0179.

MARKET FAILURE

Liabilities arising from the catastrophic train derailment
in Lac-Megantic, Quebec, which killed 47 people in July 2013 and
forced the evacuation of 2,000 people, have been conservatively
estimated as at least $1.2 billion, but could end up more than
double that amount.

In that instance, the railroad operator was covered for only
$25 million in insurance liability, and was forced to declare
insolvency, throwing the rest of the cost of the accident onto
the government.

“Shippers and rail companies are not insured against the
full liability of the consequences of incidents involving
hazardous materials,” USDOT warns. “Rail carriers and shippers
may not bear the entire cost of making whole those affected when
an incident … occurs.”

Moreover, risks and liabilities are not correctly aligned.
USDOT explains: “Shippers, although responsible for packaging
the material, and buying or leasing the tank cars in which these
products are shipped, do not generally bear any liability for an
incident once a rail carrier has accepted shipment, and rail
carriers cannot refuse shipments.”

Railroad rates cannot always be adjusted to reflect
increased risks because they are regulated by the Surface
Transportation Board.

USDOT describes under-insurance as a “market failure” and
says it justifies regulators to intervene and impose tougher
standards on the industry to bring down the probability of
catastrophic accidents.

THREAT ASSESSMENT

USDOT calculates the risks posed by oil and ethanol by rail
shipments using the same method RAND Corp has developed for
estimating risks associated with terrorism.

Risk is the product of threat, vulnerability and
consequence. In the case of oil by rail, the threat is the
probability of a major rail accident involving multiple tank
cars carrying flammable liquid. Vulnerability is the probability
flammable liquids will be released and catch fire, given an
accident has occurred. And consequence is based on estimated
damages.

Potential damages depend to a large extent on whether an
accident occurs in an uninhabited rural area, a small town, or a
densely built urban centre.

USDOT identified 36,500 miles of rail corridors being used
to transport crude and ethanol across the United States in 2012.
Population density averages about 283 persons per square
kilometre along these rail corridors, according to USDOT.

Lac-Megantic had a population density of around 272 persons
per square kilometre, and the explosions and fires were
concentrated in an area of about one square kilometre.
Lac-Megantic is, therefore, in some ways typical of the routes
along which crude and ethanol carrying trains pass.

Rural areas are much more sparsely populated, so train fires
would do less harm. But in some inner-city urban zones,
population density could be five times higher than Lac-Megantic,
which is why USDOT estimates high-end catastrophic liabilities
could reach five times as much, or $6 billion, if a train
derailed in an urban centre.

Canada’s federal government has introduced legislation that
would require railroads to obtain up to C$1 billion in insurance
cover. In addition, crude shippers will be required to
contribute C$1.65 per tonne of oil shipped to a supplementary to
cover the cost of incidents involving crude.

Lac-Megantic was an unusual disaster and unlikely to be
exactly replicated elsewhere: a high-speed crash at 65 miles per
hour involving a runaway train which resulted in the derailment
of 63 tank cars.

Most U.S. derailments have occurred at much slower speeds
and involved far fewer cars. But there are plenty of reasons to
be concerned about the catastrophic impact of even a smaller
derailment in an urban area.

The rail industry has underestimated and under-priced the
risks involved in shipping flammable liquids like crude oil and
ethanol.

These risks were hidden when only small volumes of oil and
ethanol were being moved by rail before 2008. But as shipping
volumes have soared, the incident rates has become more
apparent.

There will always be some risk involved in any commercial
activity, especially one as hazardous as the production and
distribution of flammable fuels. But 10 train fires per year,
with the probability of a catastrophic incident occurring once
every two years, is surely too high.

It is essential that regulators, railroads and shippers move
swiftly to introduce safer operating practices, and especially
more robust tank cars, before a catastrophic incident occurs.

LONDON, Feb 20 (Reuters) – EOG Resources became the
latest major shale producer to state that it would “delay a
significant number of completions” when it announced
fourth-quarter results.

The company plans to end 2015 with 285 wells awaiting
completion services, up from 200 at the end of 2014, it told
investors during an earnings call on Thursday.

Continental Resources has also announced plans to go
slow on well completions in response to the slump in oil prices.

Apache and Anadarko Petroleum are among
other shale producers to announce a deliberate strategy of
delaying completions.

U.S. shale producers are postponing well completions to
conserve cash and defer production until prices recover.

There are a large number of wells that have been drilled but
are awaiting the arrival of pressure pumping crews to fracture
them and service companies to link them up to gathering
pipelines.

In North Dakota, there were an estimated 750 wells that had
been drilled but not yet completed at the end of December,
according to the state’s Department of Mineral Resources.

Once these wells are completed, they will increase the
number of producing wells in the state by more than 8 percent,
from the current total of around 8,950.

At recent completion rates, it would take another 3-4 months
to clear the backlog even if no new wells were drilled in the
meantime.

Similar backlogs have emerged in the other shale plays. They
have been a source of frustration for producers and mineral
rights owners waiting for the oil to begin flowing and royalty
payments to start arriving.

For the most part, delays in completing wells arose
inadvertently as drilling outpaced completions during the
frenzied drilling boom in the first eight months of 2014.

But now some exploration and production companies are
deliberately postponing completions to improve their financial
performance.

“It’s a much more prudent business decision to wait. It will
give us better capital returns if we do that,” EOG’s chief
executive told analysts, in comments reported by Fuel Fix
(“Delaying completions is right business decision” Feb. 19).

PRUDENT BUSINESS

Postponing completions has a double benefit — it can cut
costs and cash outlays in the short term and enhance earnings in
the medium term.

The cost and revenue profiles for shale wells are different
from conventional ones and it is these differences that shale
producers are seeking to exploit by postponing completions.

In a conventional oil well, the cost of drilling the hole
(including casing and cementing) typically accounts for almost
all the cost. The aim is normally to complete the well, put it
into production and start recovering the capital expenditure as
quickly as possible.

But with shale wells, the need to bring in specialised
pressure pumping equipment and crews, hundreds of water tankers
and sand to fracture the rock formation and complete the well
adds a significant extra element to cost.

For some shale wells, completion costs now account for up to
two-thirds of the total. Postponing completions can defer all
these costs and help conserve significant cash in the short
term.

In other cases, producers have contracts in place with
drillers for an entire programme of work cannot cancel them
without paying substantial penalty fees, but they can then defer
completions to minimise future outlays.

Shale producers are hoping completion costs will fall in
future as prices for everything from pressure pumping equipment
to fracking sand fall amid the slump in the oil industry.

On the revenue side, the production profile of shale wells
is much more front-loaded than conventional oil wells. Initial
production during the first 30-90 days tends to be higher but
then declines faster.

In the Bakken, for example, a typical well will produce
one-third of its expected ultimate production in the first 12
months and about half in the first three years.

Revenues depend on prices from the time the well is
completed and put into production. If prices are expected to
recover, it makes sense to postpone completions, rather than
rush to finish the wells and put them into production when
wellhead prices are $50 per barrel or less.

By postponing completions, shale producers are shifting some
of their production from the first half of 2015 into the second
half or even 2016 in the hope that prices will be higher.

RIGS v COMPLETIONS

By now, it should be obvious that the number of wells
completed, rather than the number of holes drilled or rigs
operating, is more important for determining short-term changes
in oil production.

Completion delays (either unintentional or deliberate) add
another source of noise in the very unstable relationship
between rig counts and output.

Some observers have dismissed the significance of rig counts
entirely, suggesting that they provide no useful indication at
all about future production trends.

This is wrongheaded. In an ideal world, it would be nice to
have real-time data on completions, and even better on initial
production rates. In the real world, however, analysts must make
the best use of the data which is available, which in most cases
means rig counts.

While rig counts may not be perfect predictor of short-term
production changes, they are the only data available in near
real-time, and it is incorrect to state that they have no
relationship at all to output.

Completion delays, as well as variability in the quality of
rig equipment and shale wells, mean the relationship between rig
counts and production can be unstable in the short term.
Production forecasts based on rig count data must be made with
extreme care and are subject to a high degree of uncertainty.

Nonetheless, the sharp reduction in the number of rigs
operating in the United States, the smaller number of wells
being drilled, and the decision by many shale producers to
deliberately postpone completing them, all point to U.S. oil
production levelling off by the middle of the year.

LONDON (Reuters) – Consumption of gasoline and diesel in Texas is growing faster than at any time since the financial crisis, as an improving economy and lower fuel prices encourage more use of cars and trucks on the state’s roads.

Receipts of motor fuel taxes in January 2015 were 9 percent higher than the same month in 2014, according to the Texas Comptroller of Public Accounts.

Texas collected almost $288 million in motor fuel taxes last month compared with $264 million in January 2014, according to the comptroller’s monthly Revenue Watch report (link.reuters.com/heg24w).

Tax rates have not changed so the revenue rise is directly attributable to increased sales volumes.

Motor fuel taxes must be paid to the comptroller by the 25th day of the month after which they are collected by suppliers and distributors, so the January receipts are for gasoline and diesel sold in December.

By the end of last year, year-over-year collections – and by extension gasoline and diesel sales – were growing at the fastest for more than a decade.

For the last five fiscal years, motor fuel tax collections have generally increased by around 2 percent year over year.

In July 2014, before the plunge in oil prices began, fuel tax receipts were up just 2 percent compared with July 2013, in line with the five-year trend.

Once gasoline and diesel prices started to fall, however, monthly vehicle fuel sales began to pick up significantly.

According to the federal Energy Information Administration, Texas consumed 35.6 million gallons of gasoline and 20.1 million gallons of diesel every day in 2013, which was 10 percent and 13 percent of fuel consumption nationwide.

The state is the biggest consumer of diesel, and second biggest consumer of gasoline, after California, in the Union.

If the increase in driving and fuel consumption is replicated nationwide, and sustained for the rest of 2015, the United States could be on course for the largest annual increase in oil demand since at least 2004.

LONDON, Feb 17 (Reuters) – Five hundred and ninety one days
have passed since a train carrying crude oil derailed and
incinerated the town of Lac Megantic in Quebec.

In that time, the U.S. Department of Transportation (DOT)
has still not finalised new safety rules on tank car standards
and operational controls for trains carrying highly flammable
liquids.

DOT started working on new rules in April 2012 — more than
a year before the devastating fire at Lac Megantic in July 2013,
which claimed the lives of 47 people — so the process has so
far taken 1,041 days.

DOT has now sent a draft to the Office of Management and
Budget (OMB) for final review and revisions but does not expect
the final rule to be gazetted until May 12.

Even then, new tank car standards could be phased in over
several years by 2017/18, and oil shippers are pressing for an
even longer transition period.

If the timetable now sticks, it will have taken at least six
years to implement new standards for tank cars that were
recognised as necessary back in 2012. It is an astonishing
example of regulatory failure.

This is unacceptably slow. While regulators, lobbyists and
lawyers for crude shippers have been sparring in Washington over
whether new standards are necessary, and how long the industry
should be given to comply with them, crude-carrying trains have
been derailing and catching fire with frightening frequency.

On Monday, a crude-carrying train operated by CSX railroad
derailed in West Virginia, setting at least 14 tank cars
ablaze and forcing the evacuation of two nearby towns.

On the day before, a train operated by Canadian National
Railway and carrying 100 tank cars of crude derailed in
a remote part of northern Ontario and caught fire.

Since Lac Megantic, there have been at least 11 other
serious derailments across the United States and Canada
involving trains shipping large volumes of oil, according to a
tally published by the Congressional Research Service (“U.S.
rail transport of crude oil: background and issues for
Congress”, Dec 2014).

Serious incidents involving crude-carrying trains posing a
significant threat to life, property and the environment are
occurring on average once every seven weeks.

Between 2006 and April 2014, there were 16 significant
accidents involving high-hazard trains carrying crude oil or
ethanol. In total 281 tank cars derailed, nearly 5 million
gallons of crude or ethanol were released when the tank cars
were breached, and there were 48 fatalities, according to the
U.S. National Transportation Safety Board (NTSB).

So far, most of the derailments have occurred in remote
areas and small rural communities, lessening their impact, both
in terms of physical damage and political sensitivity. But it is
only a matter of time before a train derails in a major urban
area like Chicago or Albany, both of which are rail centres
handling large numbers of oil trains, causing mass casualties.

No other industry would be allowed to tolerate such an
appalling safety record.

UNSAFE TANK CARS

The problem has been extensively chronicled in accident
investigation reports by the NTSB dating as far back as 1992.

Unlike the pressure tank cars used to transport other highly
flammable or poisonous liquids, the DOT-111 design tank cars
which carry most crude and ethanol cannot reliably contain their
load in the event of an accident.

DOT-111 tank cars lack full head shields to prevent end-on
punctures in the event of a collision. Their tank walls are
significantly thinner. There is no requirement for them to have
thermal protection to protect against fire. And many have
fittings which shear off in accidents, according to NTSB (“Rail
accidents involving crude oil and ethanol releases,” April
2014).

NTSB has repeatedly warned DOT-111 tank cars are not
suitable for carrying flammable loads like crude and ethanol.
Canada has already mandated their accelerated phase-out
following Lac Megantic.

But the United States is still arguing over who should have
primary responsibility for improving train safety and how long
shippers should be given to phase out unsafe tank cars.

WHO IS RESPONSIBLE

Oil shippers argue the railroads need to do a better job of
keeping trains and tank cars on the rails, while railroads argue
shippers need to use better tank cars that will not catch fire.

Obviously, the solution requires both. In an ideal world,
tank cars should never come off the rails; the number of
derailments has indeed been alarmingly high. But accidents
happen and it is critical that when they do, tank cars should
contain their contents safely until emergency responders can
deal with the situation.

Attempts to address the safety problem have become bogged
down by fighting over whether crude is really a highly flammable
liquid (the answer to that question should be obvious by now);
whether DOT-111 tank cars are up to the job (the answer is
clearly no); and how quickly DOT-111 tank cars should be phased
out of crude service (within three years or up to a decade).

Railroad operators have made relatively speedy progress in
agreeing new rules and operating procedures for trains carrying
large volumes of crude and ethanol which went into effect in
August 2013 (“Circular OT-55-N: Recommended railroad operating
practices for transportation of hazardous materials”).

Procedures for “key trains” include lower speed limits,
heightened safety protocols which give such high-hazard trains
priority over all other traffic on the network and require more
frequent track inspections, as well as routing them around
densely-populated urban areas where possible.

Crude oil shippers have responded much more slowly, arguing
that crude is not especially dangerous and they should be given
much longer to phase out DOT-111s.

The problem is exacerbated by the allocation of liability.
Most DOT-111 tank cars are owned by shippers rather than the
railroads themselves. But in the event of an accident, it is the
railroad which is held responsible.

As common carriers, railroads must accept any cargo,
including crude, provided it is offered in a tank car with an
approved design, which at the moment includes DOT-111s.

As some railroad executives have noted, every time they
accept a dangerous consignment such as chlorine, ammonia or a
large number of oil tank cars, the potential liabilities mean
they are quite literally betting the company. In contrast,
shippers are largely exempted from liability.

PLAYING RUSSIAN ROULETTE

If the U.S. government insists on a new rule that phases out
DOT-111 tank cars from crude oil and ethanol service, the costs
will largely fall on the shippers, who will have to replace
their tank cars.

Little wonder oil shippers have tenaciously fought proposals
for an accelerated phase out of DOT-111s from oil and ethanol
service, raising concerns about the rule-making process itself
and citing limitations on how quickly more tank cars could be
ordered.

Aggressive lobbying and lawyering has slowed the regulatory
response to the problem in the United States. But it is a
short-sighted approach which is putting the entire oil-by-rail
industry in jeopardy.

With serious accidents running at one every seven weeks or
so, it is only a matter of time before one occurs in a big urban
area and causes mass casualties. In the politically charged
aftermath, the entire crude by rail will be at risk.

It is time to remove the lawyers and lobbyists from the
process and reach a top-level political and business decision
between the DOT and chief executives from both the railroads and
the shipping companies to accelerate the phase out of dangerous
DOT-111 tank cars and protect the entire industry.

LONDON, Feb 16 (Reuters) – U.S. shale producers have
responded even more quickly to lower oil prices than analysts
expected, which should ensure shale production hits a plateau by
May or June and is sustained rather than falling in the second
half of the year.

The number of rigs drilling for oil in the United States
declined by another 84 last week, according to oil field
services company Baker Hughes.

The oil-directed rig count has now fallen by a total of 553,
or 34 percent, since early October, the fastest decline since
1986.

Some analysts have questioned whether the decline in rig
counts will really result in a slowdown in oil output.

The most basic lower rigs, those with the lowest horsepower
and depth ratings, capable only of drilling vertically, are
likely to be idled first, leaving more powerful units with
horizontal capability still working.

And drilling will pull back from speculative frontier areas
to concentrate on the most productive parts of well-established
plays to maximise new output per well drilled.

But however the data is analysed a broad-based slowdown in
drilling is now occurring across the entire U.S. shale sector.

BROAD SLOWDOWN

In two of the Big Three shale plays, Williston and Permian
basins, the number of rigs drilling for oil has fallen by 34
percent, exactly in line with the national average.

Only the Eagle Ford play, where the rig count is down 28
percent, shows a slightly smaller-than-average percentage
decline.

In terms of rig capability, the number of vertical rigs is
down by 43 percent and the number of directional rigs is down by
almost 41 percent. (Directional rigs can drill slanted wells but
not fully horizontal ones.)

But even the number of horizontal drilling rigs is down by
24 percent, taking 328 horizontal rigs out of operation since
early October.

Horizontal rigs (328) account for almost 60 percent of all
units taken out of service since Oct. 10 (572), according to
Baker Hughes.

The extent of the slowdown comes as no surprise. In
December, Continental Resources, one of the biggest
producers in the Bakken, announced it would cut the number of
rigs operating from around 50 to 34 by the end of the first
quarter (32 percent) and an average of 31 for the whole of 2015
(38 percent).

Nonetheless, the slowdown has occurred even faster than
expected as ultra-low prices in January sent a shock through the
entire production community.

The bravado with which shale drillers greeted falling prices
in October and November, openly challenging to OPEC to do its
worst, reminiscent of President George W Bush’s “bring ‘em on”,
has evaporated.

Now shale producers are focused on restructuring their
operations and conserving cash to survive until prices recover.

BREAKING EVEN AGAIN

The faster-than-expected response from producers has helped
oil prices rise from their mid-January lows to a more
sustainable level.

Front-month Brent prices are up 31 percent from less than
$47 on Jan. 13 to $62. WTI has risen 20 percent from $44 on Jan.
29 to $53.

Plains Marketing posted prices for Bakken sweet are up 28
percent from just $28 on Jan. 28 to more than $36. Texas posted
prices have risen by around 20 percent from $41 to $49 a barrel.

In January, oil prices had fallen to levels at or below
breakeven levels for even the best parts of the major shale
plays and obviously unsustainable.

But the rebound should ensure drilling in the best
properties within the core areas of the Big Three is just about
sustainable.

Based on a simple average of posted prices and WTI, wellhead
prices in North Dakota have risen to almost $45 per barrel.

Wellhead prices are now at or above the breakeven levels
needed in all four counties at the heart of the Bakken play
(Dunn, McKenzie, Mountrail and Williams) according to estimates
published last month by North Dakota’s Department of Mineral
Resources (DMR).

These four counties together accounted for more than 1
million barrels per day of the state’s total production of 1.23
million in December.

Wellhead prices are now much closer to the level needed to
sustain North Dakota’s output at around 1.2 million barrels per
day throughout the rest of the year and 2016.

The same is true in Texas, where wellhead prices are close
to $50 per barrel in much of the state.

SUSTAINING OUTPUT

Prices have responded faster than the Energy Information
Administration (EIA) predicted in its January Short-Term Energy
Outlook (STEO).

EIA forecast Brent prices would gradually climb to around
$54 by May and end the year at $70, with WTI recovering to $51
and $67 respectively.

The agency’s projected price rebound underpinned its
prediction that crude production would end the year at about the
same level as it began, after dipping between May and September.

In fact, prices have recovered slightly ahead of that
timetable. Crude prices no longer appear severely undervalued or
out of line with underlying supply and demand.

The faster-than-expected price recovery, if it is sustained,
would help support oil production around current levels and
ensure it hits a plateau, rather than declines, over the summer
months and into the end of the year.

LONDON, Feb 13 (Reuters) – “This is the really crappy part
of the job, and this is what I hate about this industry
frankly,” the chief executive of oilfield services company Baker
Hughes complained as he announced it would lay off 7,000
employees.

Baker Hughes is cutting jobs in response to slumping prices
and a downturn in drilling activity.

But the company’s obviously frustrated chief acknowledged
that “this is the industry, and it’s throwing us another one of
these downturns, and we’re going to be good stewards of our
business and do the right thing.”

So the company will cuts costs, he told investors in a
conference call on January 20 to discuss the firm’s
fourth-quarter earnings and outlook for 2015.

More than 100,000 layoffs have been announced across the
industry worldwide since prices began to slide last summer,
according to a tally kept by Bloomberg.

In recent weeks other major service companies have announced
job reductions. Halliburton announced it will cut 6,400
jobs (8 percent of its global workforce) while Schlumberger
will eliminate 9,000 positions (around 7 percent of its
workforce).

Precision Drilling, one of the largest rig
contractors in North America, has idled more than 50 of the 250
rigs it had working this time last year, leaving more than 1,000
skilled operators out of work, the company said on Thursday.

“Industry downturns are difficult for all, but they affect
our rig crews more than anybody else,” the company’s chief
executive said in a statement.

“Precision recruited, trained and developed many excellent
crews to support the demands of our customers over the past
several years, and unfortunately we now don’t have work for many
of these dedicated workers.”

HUMAN CAPITAL

Tens of thousands more jobs have been cut, through layoffs
or retirements, across every part of the industry, ranging from
self-employed drilling contractors and well-completion crews to
full-service companies, seismic surveyors and of course the oil
and gas producers themselves.

Oil and gas production is an exceptionally capital-intensive
industry. But the sector’s most important and scarce resource is
its workforce.

The oil industry’s popular image may be a roughneck in
soiled overalls drinking in a strip joint, but it has an
enormous demand for highly skilled and, during a boom, very well
compensated workers.

Modern oil and gas production is technically complicated and
dangerous work. The days of drilling wildcat wells more or less
at random and allowing the well to blow out in a massive gusher
are long over.

The industry still provides employment for unskilled casual
labour. In boom times some of the jobs for truck drivers and
other support staff can be exceptionally well paid.

But at its core are tens of thousands of petroleum engineers
and petroleum geoscientists, as well as tool pushers, drillers,
derrickmen and roughnecks on the rigs themselves, who perform
specialised functions which demand years of formal education
and, most importantly, experience in the field.

The challenge is recruiting, training and retaining these
workers and maintaining an appropriate long-term labour force
profile in an industry stuck with a profound boom-bust cycle and
beset by periodic mass layoffs.

THE GREAT CREW CHANGE

Until recently, the oil industry was preoccupied by a
looming shortage of skilled workers — especially mid-career
professionals ready to step into supervisory and senior
leadership roles.

Schlumberger’s consulting arm, which offers human resources
planning advice to third parties, has warned repeatedly about
“the looming talent shortage” as a result of what it termed “the
great crew change”.

Oil and gas companies have lots of experienced workers in
their late 40s and 50s, and have recently succeeded in
attracting more young graduates. But there is an acute shortage
of mid-career professionals aged 35-45, with 10-20 years
training and experience.

The large number of professionals in their 50s poses a major
problem as they reach the age for retirement, while recent
graduates are still 10-15 years away from being ready to assume
supervisory positions.

The industry’s uneven age profile is the legacy of the last
downturn during the late 1980s and through the 1990s, when low
oil prices and the squeeze on profits resulted in enormous job
losses and a virtual freeze on hiring.

As a result, the cohort of workers recruited in the mid and
late 1990s, who should be moving into supervisory and eventually
leadership positions, is unusually small.

Back in 2013, Schlumberger predicted the oil and gas
industry would have a shortage of around 15,000 experienced
petroleum engineers and geoscientists by 2016.

The predicted shortfall of experienced petro-technical
professionals (PTPs) would approach 20 percent of the total
required number.

The looming shortage was seen by many as the biggest single
threat to increasing oil and gas supplies in the second half of
the current decade and into the 2020s.

GRADUATE RECRUITS

Schlumberger forecast the industry would need to hire 10,000
new petro-technical professionals every year through 2020 to
offset retirements and meet the need for expansion.

The oil industry spent years working to encourage more
college students to specialise in petroleum engineering and
related disciplines.

Petroleum engineering departments hired extra instructors
and increased enrolments. According to the U.S. Department of
Education, the number of students enrolled in petroleum
engineering programmes at U.S. universities increased from a
recent low of just 561 in 1997 to 1,301 in 2011 (link.reuters.com/tux93w).

Now, of course, the downturn has thrown thousands of oil and
gas professionals out of work, and led to pay freezes and cuts
in contracting rates.

Amid all the headlines about layoffs, falling salaries and a
potentially prolonged downturn in oil prices, the industry
somehow has to avoid losing current graduates to other sectors
and continue encouraging high school students that oil and gas
engineering and science is an attractive long-term career.

Because if the oil industry cannot maintain an adequate
skill base, with the right age structure, skill shortages will
re-emerge and set the stage for the next brutal boom-bust cycle.

In practice, the industry has never succeeded in balancing
long-term personnel planning with the short-term financial
imperative to control the wage bill.

It may not be any more successful this time around, if the
slump in oil prices and drilling continues long enough.

And that’s why the chief executive of Baker Hughes could say
truthfully mass lay-offs are what he and everyone else “hates”
most about the oil and gas industry.